The recovery of hydrocarbons from subterranean zones relies on the process of drilling wellbores. The process includes drilling equipment situated at surface and a drill string extending from the surface equipment to the formation or subterranean zone of interest. The drill string can extend thousands of meters below the surface. The terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore. In addition to this conventional drilling equipment the system also relies on some sort of drilling fluid, which in most cases is a drilling “mud” which is pumped through the inside of the drill string. The drilling mud cools and lubricates the drill bit and then exits out of the drill bit and carries rock cuttings back to surface. The mud also helps control bottom hole pressure and prevents hydrocarbon influx from the formation into the wellbore, which can potentially cause a blow out at surface.
Directional drilling is the process of steering a well away from vertical to intersect a target endpoint or to follow a prescribed path. At the terminal end of the drill string is a bottom-hole-assembly (“BHA”) which comprises 1) a drill bit; 2) a steerable downhole mud motor of rotary steerable system; 3) sensors of survey equipment (logging-while-drilling (LWD) and/or measurement-while-drilling (MWD)) to evaluate downhole conditions as well depth progresses; 4) equipment for telemetry of data to surface; and 5) other control mechanisms such as stabilizers or heavy weight drill collars. The BHA is conveyed into the wellbore by a metallic tubular.
As an example of a potential drilling activity, MWD equipment is used to provide downhole sensor and status information to surface in a near real-time mode while drilling. This information is used by the rig crew to make decisions about controlling and steering the well to optimize the drilling speed and trajectory based on numerous factors, including lease boundaries, locations of existing wells, formation properties, and hydrocarbon size and location. This can include making intentional deviations from an originally-planned wellbore path as necessary based on the information gathered from the downhole sensors during the drilling process. The ability to obtain real time data during MWD allows for a relatively more economical and more efficient drilling operation.
In both directional and straight (or vertical) holes, the position of the well must be known with reasonable accuracy to ensure the correct well trajectory. While extending the wellbore, evaluation of physical properties such as pressure, temperature and the wellbore trajectory in three-dimensional space are important. The measurements include inclination from vertical and azimuth (compass heading). Measurements are typically made at discrete points with the general path of the wellbore computed from these points. In downhole MWD, the MWD tool surveys the well as it is drilled and information regarding the orientation of the drill bit is relayed back to the driller on surface. Measurement devices typically include a series of accelerometers which measure the inclination of the tool (for example vertical is 0° inclination and horizontal is 90° inclination) and magnetometers which measure the earth's magnetic field to determine azimuth. A typical Directional and Inclination (D&I) sensor package consists of three single axis accelerometers in each of the three orthogonal axes, together with two dual axes magnetometers yielding the three orthogonal axes and one redundant axis, which is typically not used. The sensor package also includes associated data acquisition and processing circuitry. The accelerometers and magnetometers are arranged in three mutually orthogonal directions, and measure the three mutually orthogonal components of the Earth's magnetic field and Earth's gravity. The accelerometer consists of a quartz crystal suspended in an electromagnetic field; measuring the inclination by how much electromagnetic force is required to maintain the crystal in balance. The accelerometers provide measurement of deviation from vertical, or inclination, as well as providing a measurement of the toolface or rotational orientation of the tool. The magnetometers provide a measure of the direction or magnetic heading as well as its orientation when the BHA is at or near vertical. These sets of measurements combined assist the driller for steering as well as for computing location. In most cases, whenever another length of drill pipe is added to the drill string, a survey is taken and the information is sent to surface and decoded by the MWD tool operator and converted to information the driller requires for survey calculations. The BHA position is then calculated by assuming a certain trajectory between the surveying points.
Gyroscopes may also be used to help determine direction of the BHA and for identification or correlation of angular changes for particular formation parameters as measured. Similar to placement of accelerometers and magnetometers, there may be three gyroscopes oriented in the x, y and z orthogonal axes within a gyroscope unit. Unlike magnetometers, gyroscopes are not adversely affected by the presence of ferrous metals. Gyroscopes however, tend to be more complex and have time-dependent errors which require the gyroscopes to be re-referenced or calibrated after exposure to high temperature and vibration. Gyroscopes also tend not to give good toolface direction at low inclination.
U.S. Pat. No. 8,061,048, which is incorporated herein by reference, describes the use in open or cased holes, of three gyroscopes, at three angular orthogonal orientations to each other, used to determine the direction of north and then azimuth. U.S. Pat. No. 7,801,704 which is incorporated herein by reference, describes benefits of industry available MEMS gyro sensors which are cheap, light weight, shock reliable, high temperature resistant and have low offset error. Azimuthal measurements with gyroscopes are preferably conducted under stationary conditions. Instead of magnetic north, gyroscopes can relate azimuthal direction of borehole to true north. As described in U.S. Pat. No. 8,200,436 and U.S. Pat. No. 8,260,554 (incorporated herein by reference) gyroscopes combined with accelerometers can provide inertial tracking of tool position, particularly in situations where magnetic field is disrupted such as within or close to a metal casing. In U.S. Pat. No. 7,234,540 (incorporated herein by reference), two axes gyroscopes are used to determined toolface angle making use of inherent slight misalignment of one gyroscope and its resultant sensitivity to rotation about the third axis. In addition, temperature dependent errors are removed in the method of calibration by cross-sensitivity of the two gyroscopes about the third axis.
Known MWD tools contain essentially the same D&I sensor package to survey the well bore but the data may be sent back to surface by various telemetry methods. Such telemetry methods include, but are not limited to, the use of hardwired drill pipe, acoustic telemetry, fibre optic cable, Mud Pulse (MP) Telemetry and Electromagnetic (EM) Telemetry. In some downhole drilling operations there may be more than one telemetry system used to provide a backup system in case one of the wellbore telemetry systems fails or is otherwise unable to function properly. The sensors used in the MWD tools are usually located in an electronics probe or instrumentation assembly contained in a cylindrical cover or housing, located near the drill bit.
In directional drilling, the operator may utilize one or more horizontal well bores that branch from a single vertical well bore to utilize productive hydrocarbon deposits. The various formations being drilled through are composed of different layers of source material. In many cases, the driller and geologist rely on various formation parameters to help identify and verify that the drill bit is within or close to the zone of interest. One such parameter is gamma radiation which is naturally emitted by different isotopes, generally potassium, uranium and thorium. Gamma radiation emissions tend to be uniform within a particular zone and exhibit similar emission levels based on the type of source rock. For example, sandstones (which are generally hydrocarbon bearing) have low gamma radiation emission, whereas shale (which generally define sandstone bed boundaries) typically have a higher gamma radiation emission level. The variance in the gamma radiation emissions between these two types of rock can by used to help identify where the drill bit is positioned within a zone. For example, if the gamma radiation emissions begin to increase, the drill bit may be closer in proximity to a shale boundary and hence deviating away from the zone of interest.
Traditional gamma radiation counters use scintillation crystals and photomultiplier tubes disposed within pressure housing secured in a rotating portion of the drill string. The crystal reacts to the emitted gamma radiation, with the captured optical energy transferred to electrical energy through the electronics assembly, and the data is relayed to the telemetry system. Traditional gamma counters provide levels of detected emissions from the surrounding formation wellbore, but do not provide the angular location of the gamma radiation. It is beneficial for the driller to know directional aspects of gamma radiation to provide an indication of the proximity or closeness to upper and lower boundaries of formations. The driller will try to stay within a specific target or “pay area” of the zone of interest; even when the formation dips the driller will try to stay within the anticipated pay area as these are the most productive vertical meters within the formation.
More recently, directional information has been added to gamma radiation measurement with “focused gamma counters”. This has been accomplished by installing the scintillation crystal in such as way as to limit the crystal's “window of exposure” to a defined angular open window in a shield housing placed around the crystal. The shield housing blocks or reduces capture of emitted radiation except for gamma radiation hitting the crystal through the open window as described in U.S. Pat. No. 6,300,624 and U.S. Pat. No. 6,944,548, both of which are incorporated herein by reference. The window is rotated as the drill string rotates, and gamma radiation measurements for the full 360 degree circumference around the borehole may be captured. Normally, gamma radiation measurements in a particular zone of interest are approximately azimuthally uniform because the pay area consists mostly of one material, such as sand. As the BHA nears a bed boundary, the focused gamma sensor will detect a variation in gamma radiation measurements, with the highest amplitude or counts being recorded when the open window faces the bed boundary. Typically in focused gamma, the measurements are taken while holding a specific toolface. Once gamma radiation measurements are taken, the tool is rotated to a new toolface position and then held there as a new set of measurements are taken, and repeated. In other focussed gamma counters, such as those described in U.S. Pat. No. 6,300,624, multiple gamma counters are placed in sondes each facing a different direction to capture the angular variation of the gamma radiation from the surrounding formation without having to rotate the detector.
In CA 2,367,023 (incorporated herein by reference), the microcontroller in the tool divides the circumference of the tool into a predetermined number of wedges and a gamma radiation count value is assigned for each wedge or sector. The x and y components of the gamma radiation counts for each sector are determined and averaged to obtain the average x and y components.